It is desirable during the production of oil and gas to carry out flow measurements to determine the flow properties of individual phases of multiphase flow. In particular, measurement of the flow rates of e.g. oil, gas and water in a conduit, such as a pipe, is highly desirable.
However, in general it is very difficult to obtain measurements of the flow of the different phases when they flow simultaneously through a pipe.
This difficulty is primarily due to the wide variety of flow regimes such a multiphase flow can take. For example, the three phases can be well mixed together with one as the continuous phase and the other two dispersed within it. Mostly there may be phase separation between gas and liquid with the liquid often moving at a much lower velocity than the gas.
When gas is the dominant phase, a commonly encountered flow regime is for the gas to travel along the centre of the pipe with dispersed droplets of oil and water within it, whilst the majority of the oil and water travels along the pipe wall which itself may comprise entrained gas bubbles.
Additionally, flow phase and velocity distributions may alter both spatially and temporally. Sudden or gradual variation in flow rates of one phase or another may cause a change in flow regime. Also, due to the high pressure encountered deep underground, a flow which is mixed or in bubble-flow can become dominated by a discernible high gas-fraction flow as the pressure drops nearer the surface and the gas expands and/or comes out of solution.
Multiphase flowmeters are available and have been suggested in the prior art. However, these operate to give accurate readings only for particular flow regimes.
For example, GB 2426579 and GB 2450182 teach the use of an optical system using two wavelengths of light, one which is water-absorbing and one which is substantially not. By analysing the transmitted light and scattered light at both wavelengths, information on water content is obtainable. Flow rates may also be obtained by analysing transmitted and/or scattered signals measured by duplication of the sensors axially spaced. However, this system only works well for flow regimes with very high gas volume fractions (GVF>˜99%), typically with very thin (i.e. <1 mm) liquid layers flowing on the pipe wall and/or with a gas flow at the centre which may contain entrained liquid droplets. At lower gas volume fractions (GVF) a thicker liquid layer can prevent any transmission of light across the pipe, preventing measurements from being taken.
WO 2009/071870 teaches the use of pulsed echo ultrasound to measure the thickness of a separated liquid layer at the pipe without needing to know the speed of sound in the liquid by comparing echoes received from two transducers, one of which is aligned perpendicular to the pipe wall and the other aligned at an angle to the pipe wall. Flow velocities of the liquid layer may be obtainable from the use of pulsed Doppler ultrasound, together with a measure of the speed of sound in the liquid. The speed of sound in the gas-free liquid can be used to infer the water fraction of the liquid, or the water-to-liquid ratio (WLR). However, as the speed of sound in oil and water can be somewhat similar, this measure of water fraction tends to be inaccurate.
The use of electromagnetic methods, such as microwaves, has also been suggested. GB 2376074 teaches the use of a microwave open-ended coaxial reflection probe flush-mounted on the pipe wall to measure the mixture permittivity and mixture conductivity of liquid-layer to obtain an estimate of water conductivity, as well as an estimate of the water-to-liquid ratio if the liquid layer is substantially free from entrained gas and has a thickness higher than the probe's depth of investigation.
However, at high gas volume fractions, when the thickness of the liquid at the wall of the pipe becomes thin and less than the sensitivity depth of the probe in most instance of time, the probe can also inadvertently measure the properties of the adjacent gas core, providing erroneous results in the water-to-liquid ratio.
GB 2430493 utilises a transmission electromagnetic approach, as opposed to a reflective electromagnetic approach, in combination with venturi and gamma radiation sensors. The transmission microwaves are used to measure the mixture permittivity and mixture conductivity across the whole of the pipe. The gamma rays are employed to measure the average fluid density across pipe, which is used to infer the gas-to-liquid ratio. By employing density and permittivity and/or conductivity mixing rules, measures of water fraction, oil fraction and gas fraction, and hence estimate of the water-to-liquid ratio, can be obtained. The measured venturi differential pressure and/or further microwave sensors in the venturi can be used to provide flow rate and/or velocity data.
However, at very high gas volume fractions, the microwave transmission approach produces low values of bulk mixture permittivity and mixture conductivity, due to, for example, the thin liquid layer at the pipe wall, and so derived phase-fraction quantities can become inaccurate. Additionally gamma-ray measurement methods are also less accurate at high gas volume fractions, and are undesirable because of environmental and regulatory restrictions on their use.